On 23 August 2017, the Department of Energy (DOE) issued a report entitled, “Staff Report to the Secretary on Energy Markets and Reliability.” In his cover letter, Energy Secretary Rick Perry notes:

“It is apparent that in today’s competitive markets certain regulations and subsidies are having a large impact on the functioning of markets, and thereby challenging our power generation mix. It is important for policy makers to consider their intended and unintended effects.”

Among the consequences of the national push to implement new generation capacity from variable renewable energy (VRE) resources (i.e., wind & solar) are: (1) increasing grid perturbations due to the variability of the output from VRE generators, and (2) early retirement of many baseload generating plants because of several factors, including the desire of many states to meet their energy demand with a generating portfolio containing a greater percentage of VRE generators. Grid perturbations can challenge the reliability of the U.S. bulk power systems that comprise our national electrical grid. The reduction of baseload capacity reduces the resilience of the bulk power system and its ability dampen these perturbations.

The DOE staff report contains the following typical daily load curve. Baseload plants include nuclear and coal that operate at high capacity factor and generally do not maneuver in response to a change in demand. The intermediate load is supplied by a mix of generators, including VRE generators, which typically operate at relatively low capacity factors. The peak load generators typically are natural gas power plants that can maneuver or be cycled (i.e., on / off) as needed to meet short-term load demand. The operating reserve is delivered by a combination of power plants that can be reliably dispatched if needed.

The trends in new generation additions and old generation retirements is summarized in the following graphic from the DOE staff report.

Here you can see that recent additions (since 2006) have focused on VRE generators (wind and solar) plus some new natural gas generators. In that same period, retirements have focused on oil, coal and nuclear generators, which likely were baseload generators.

The DOE staff report noted that continued closure of baseload plants puts areas of the country at greater risk of power outages. It offered a list of policy recommendations to reverse the trend, including providing power pricing advantages for baseload plants to continue operating, and speeding up and reducing costs for permitting for baseload power and transmission projects.

Regarding energy storage, the DOE staff report states the following in Section 4.1.3:

“Energy storage will be critical in the future if higher levels of VRE are deployed on the grid and require additional balancing of energy supply and demand in real time.”

“DOE has been investing in energy storage technology development for two decades, and major private investment is now active in commercializing and the beginnings of early deployment of grid-level storage, including within microgrids.”

Options for energy storage are identified in the DOE staff report.

You can download the DOE staff report to the Secretary and Secretary Perry’s cover letter here:

Lyncean members should recall our 2 August 2017 meeting and the presentation by Patrick Lee entitled, “A fast, flexible & coordinated control technology for the electric grid of the future.” This presentation described work by Sempra Energy and its subsidiary company PXiSE Energy Solutions to address the challenges to grid stability caused by VRE generators. An effective solution has been demonstrated by adding energy storage and managing the combined output of the VER generators and the energy storage devices in real-time to match supply and demand and help stabilize the grid. This integrated solution, with energy storage plus real-time automated controls, appears to be broadly applicable to VRE generators and offers the promise, especially in Hawaii and California, for resilient and reliable electrical grids even with a high percentage of VRE generators in the state’s generation portfolio.

You can download Patrick Lee’s 2 August 2017 presentation to the Lyncean Group of San Diego at the following link:

My 31 January 2015 post, “Flow Cell Battery Technology Being Tested as an Automotive Power Source,” addressed flow cell battery (also known as redox flow cell battery) technology being applied by the Swiss firm nanoFlowcell AG for use in automotive all-electric power plants. The operating principles of their nanoFlowcell® battery are discussed here:

This flow cell battery doesn’t use rare or hard-to-recycle raw materials and is refueled by adding “bi-ION” aqueous electrolytes that are “neither toxic nor harmful to the environment and neither flammable nor explosive.” Water vapor is the only “exhaust gas” generated by a nanoFlowcell®.

The e-Sportlimousine and the QUANT FE cars successfully demonstrated a high-voltage electric power automotive application of nanoFlowcell® technology.

Since my 2015 post, flow cell batteries have not made significant inroads as an automotive power source, however, the firm now named nanoFlowcell Holdings remains the leader in automotive applications of this battery technology. You can get an update on their current low-voltage (48 volt) automotive flow cell battery technology and two very stylish cars, the QUANT 48VOLT and the QUANTiNO, at the following link:

In contrast to most other electric car manufacturers, nanoFlowcell Holdings has adopted a low voltage (48 volt) electric power system for which it claims the following significant benefits.

“The intrinsic safety of the nanoFlowcell® means its poles can be touched without danger to life and limb. In contrast to conventional lithium-ion battery systems, there is no risk of an electric shock to road users or first responders even in the event of a serious accident. Thermal runaway, as can occur with lithium-ion batteries and lead to the vehicle catching fire, is not structurally possible with a nanoFlowcell® 48VOLT drive. The bi-ION electrolyte liquid – the liquid “fuel” of the nanoFlowcell® – is neither flammable nor explosive. Furthermore, the electrolyte solution is in no way harmful to health or the environment. Even in the worst-case scenario, no danger could possibly arise from either the nanoFlowcell® 48VOLT low-voltage drive or the bi-ION electrolyte solution.”

In comparison, the more conventional lithium-ion battery systems in the Tesla, Nissan Leaf and BMW i3 electric cars typically operate in the 355 – 375 volt range and the Toyota Mirai hydrogen fuel cell electric power system operates at about 650 volts.

In the high-performance QUANT 48VOLT “supercar,” the low-voltage application of flow cell technology delivers extreme performance [560 kW (751 hp), 300 km/h (186 mph) top speed] and commendable range [ >1,000 kilometers (621 miles)]. The car’s four-wheel drive system is comprised of four 140 kW (188 hp), 45-phase, low-voltage motors and has been optimized to minimize the volume and weight of the power system relative to the previous high-voltage systems in the e-Sportlimousine and QUANT FE.

The smaller QUANTiNO is designed as a practical “every day driver.” You can read about a 2016 road test in Switzerland, which covered 1,167 km (725 miles) without refueling, at the following link:

A version of the QUANTiNO without supercapacitors currently is being tested. In this version, the energy for the electric motors comes directly from the flow cell battery, without any buffer storage in between. These tests are intended to refine the battery management system (BMS) and demonstrate the practicality of an even simpler, but lower performance, 48-volt power system.

Both the QUANT 48VOLT and QUANTiNO were represented at the 2017 Geneva Auto Show.

I think the automotive applications of flow cell battery technology look very promising, particularly with the long driving range possible with these batteries, the low environmental impact of the electrolytes, and the inherent safety of the low-voltage power system. I wouldn’t mind having a QUANT 48VOLT or QUANTiNO in my garage, as long as I could refuel at the end of a long trip.

Electrical utility-scale applications of flow cell batteries

In my 4 March 2016 post, “Dispatchable Power from Energy Storage Systems Help Maintain Grid Stability,” I noted that the reason we need dispatchable grid storage systems is because of the proliferation of grid-connected intermittent generators and the need for grid operators to manage grid stability regionally and across the nation. I also noted that battery storage is only one of several technologies available for grid-connected energy storage systems.

Flow cell battery technology has entered the market as a utility-scale energy storage / power system that offers some advantages over more conventional battery storage systems, such as the sodium-sulfur (NaS) battery system offered by Mitsubishi, the lithium-ion battery systems currently dominating this market, offered by GS Yuasa International Ltd. (system supplied by Mitsubishi), LG Chem, Tesla, and others, and the lithium iron phosphate (LiFePO4) battery system being tested in California’s GridSaverTM program. Flow cell battery advantages include:

Flow cell batteries have no “memory effect” and are capable of more than 10,000 “charge cycles”. In comparison, the lifetime of lead-acid batteries is about 500 charge cycles and lithium-ion battery lifetime is about 1,000 charge cycles. While a 1,000 charge cycle lifetime may be adequate for automotive applications, this relatively short battery lifetime will require an inordinate number of battery replacements during the operating lifetime of a utility-scale, grid-connected energy storage system.

The energy converter (the flow cell) and the energy storage medium (the electrolyte) are separate. The amount of energy stored is not dependent on the size of the battery cell, as it is for conventional battery systems. This allows better storage system scalability and optimization in terms of maximum power output (i.e., MW) vs. energy storage (i.e., MWh).

No risk of thermal runaway, as may occur in lithium-ion battery systems

The firm UniEnergy Technologies (UET) offers two modular energy storage systems based on flow cell battery technology: ReFlex and the much larger Uni.System™, which can be applied in utility-scale dispatchable power systems. UET describes the Uni.System™ as follows:

“Each Uni.System™ delivers 600kW power and 2.2MWh maximum energy in a compact footprint of only five 20’ containers. Designed to be modular, multiple Uni.System can be deployed and operated with a density of more than 20 MW per acre, and 40 MW per acre if the containers are double-stacked.”

The website Global Energy World reported that UET recently installed a 2 MW / 8 MWh vanadium flow battery system at a Snohomish Public Utility District (PUD) substation near Everett, Wash. This installation was one of five different energy storage projects awarded matching grants in 2014 through the state’s Clean Energy Fund. See the short article at the following link:

“The utility is managing its energy storage projects with an Energy Storage Optimizer (ESO), a software platform that runs in its control center and maximizes the economics of its projects by matching energy assets to the most valuable mix of options on a day-ahead, hour-ahead and real-time basis.”

You can read more about these Snohomish PUD energy storage systems at the following link:

The design of both Snohomish PUD systems are based on the Modular Energy Storage Architecture (MESA), which is described as, “an open, non-proprietary set of specifications and standards developed by an industry consortium of electric utilities and technology suppliers. Through standardization, MESA accelerates interoperability, scalability, safety, quality, availability, and affordability in energy storage components and systems.” You’ll find more information on MESA standards here:

On 9 January 2014 the Administration launched a “Quadrennial Energy Review” (QER) to examine “how to modernize the Nation’s energy infrastructure to promote economic competitiveness, energy security, and environmental responsibility…” You can read the Presidential Memorandum establishing the QER at the following link:

On April 21, 2015, the QER Task Force released the “first installment” of the QER report entitled “Energy Transmission, Storage, and Distribution Infrastructure.” The Task Force announcement stated:

“The first installment (QER 1.1) examines how to modernize our Nation’s energy infrastructure to promote economic competitiveness, energy security, and environmental responsibility, and is focused on energy transmission, storage, and distribution (TS&D), the networks of pipelines, wires, storage, waterways, railroads, and other facilities that form the backbone of our energy system.”

The complete QER 1.1 report or individual chapters are available at the following link:

On January 6, 2017, the QER Task Force released the “second installment” of the QER report entitled “Transforming the Nation’s Electricity System.” The Task Force announcement stated:

“The second installment (QER 1.2) finds the electricity system is a critical and essential national asset, and it is a strategic imperative to protect and enhance the value of the electricity system through modernization and transformation. QER 1.2 analyzes trends and issues confronting the Nation’s electricity sector out to 2040, examining the entire electricity system from generation to end use, and within the context of three overarching national goals: (1) enhance economic competitiveness; (2) promote environmental responsibility; and (3) provide for the Nation’s security.

The report provides 76 recommendations that seek to enable the modernization and transformation of the electricity system. Undertaken in conjunction with state and local governments, policymakers, industry, and other stakeholders, the recommendations provide the building blocks for longer-term, planned changes and activities.”

The complete QER 1.2 report or individual chapters are available at the following link:

I hope you take time to explore the QERs. I think the Task Force has collected a great deal of actionable information in the two reports. Converting this information into concrete actions will be a matter for the next Administration.

In my 17 December 2016 post, “Climate Change and Nuclear Power,” there is a chart that shows the results of a comparative life cycle greenhouse gas (GHG) analysis for 10 electric power-generating technologies. In that chart, it is clear how carbon dioxide capture and storage technologies can greatly reduce the GHG emissions from gas and coal generators.

An overview of carbon dioxide capture and storage technology is presented in a December 2010 briefing paper issued by the London Imperial College. This paper includes the following process flow diagram showing the capture of CO2 from major sources, use or storage of CO2 underground, and use of CO2 as a feedstock in other industrial processes. Click on the graphic to enlarge.

You can download the London Imperial College briefing paper at the following link:

Here is a brief look at selected technologies being developed for underground storage (sequestration) and industrial utilization of CO2.

Store in basalt formations by making carbonate rock

Iceland generates about 85% of its electric power from renewable resources, primarily hydro and geothermal. Nonetheless, Reykjavik Energy initiated a project called CarbFix at their 303 MWe Hellisheidi geothermal power plant to control its rather modest CO2 emissions along with hydrogen sulfide and other gases found in geothermal steam.

Hellisheidi geothermal power plant. Source: Power Technology

The process system collects the CO2 and other gases, dissolves the gas in large volumes of water, and injects the water into porous, basaltic rock 400 – 800 meters (1,312 – 2,624 feet) below the surface. In the deep rock strata, the CO2 undergoes chemical reactions with the naturally occurring calcium, magnesium and iron in the basalt, permanently immobilizing the CO2 as environmentally benign carbonates. There typically are large quantities of calcium, magnesium and iron in basalt, giving a basalt formation a large CO2 storage capacity.

The surprising aspect of this process is that the injected CO2 was turned into hard rock very rapidly. Researchers found that in two years, more that 95% of the CO2 injected into the basaltic formation had been turned into carbonate.

For more information, see the 9 June 2016 Washington Post article by Chris Mooney, “This Iceland plant just turned carbon dioxide into solid rock — and they did it super fast,” at the following link:

“The researchers are enthusiastic about their possible solution, although they caution that they are still in the process of scaling up to be able to handle anything approaching the enormous amounts of carbon dioxide that are being emitted around the globe — and that transporting carbon dioxide to locations featuring basalt, and injecting it in large volumes along with even bigger amounts of water, would be a complex affair.”

Basalt formations are common worldwide, making up about 10% of continental rock and most of the ocean floor. Iceland is about 90% basalt.

Detailed results of this Reykjavik Energy project are reported in a May 2016 paper by J.M. Matter, M. Stute, et al., “Rapid carbon mineralization for permanent disposal of anthropogenic carbon dioxide emissions,” which is available on the Research Gate website at the following link:

Similar findings were made in a separate pilot project in the U.S. conducted by Pacific Northwest National Laboratory and the Big Sky Carbon Sequestration Partnership. In this project, 1,000 tons of pressurized liquid CO2 were injected into a basalt formation in eastern Washington state in 2013. Samples taken two years later confirmed that the CO2 had been converted to carbonate minerals.

These results were published in a November 2016 paper by B. P McGrail, et al., “Field Validation of Supercritical CO2 Reactivity with Basalts.” The abstract and the paper are available at the following link:

Lawrence Berkeley National Laboratory has established an initiative dubbed SubTER (Subsurface Technology and Engineering Research, Development and Demonstration Crosscut) to study how rocks fracture and to develop a predictive understanding of fracture control. A key facility is an observatory set up 1,478 meters (4,850 feet) below the surface in the former Homestake mine near Lead, South Dakota (note: Berkeley shares this mine with the neutrino and dark matter detectors of the Sanford Underground Research Facility). The results of the Berkeley effort are expected to be applicable both to energy production and waste storage strategies, including carbon capture and sequestration.

You can read more about this Berkeley project in the article, “Underground Science: Berkeley Lab Digs Deep For Clean Energy Solutions,” on the Global Energy World website at the following link:

Researchers at the Department of Energy’s Oak Ridge National Laboratory (ORNL) have defined an efficient electrochemical process for converting CO2 into ethanol. While direct electrochemical conversion of CO2 to useful products has been studied for several decades, the yields of most reactions have been very low (single-digit percentages) and some required expensive catalysts.

Key points about the new process developed by ORNL are:

The electro-reduction process occurs in CO2 saturated water at ambient temperature and pressure with modest electrical requirements

The nanotechnology catalyst is made from inexpensive materials: carbon nanospike (CNS) electrode with electro-nucleated copper nanoparticles (Cu/CNS). The Cu/CNS catalyst is unusual because it primarily produces ethanol.

Process yield (conversion efficiency from CO2 to ethanol) is high: about 63%

The process can be scaled up.

A process like this could be used in an energy storage / conversion system that consumes extra electricity when it’s available and produces / stores ethanol for later use.

You can read more on this process in the 19 October 2016 article, “Scientists just accidentally discovered a process that turns CO2 directly into ethanol,” on the Science Alert website at the following link

The IEA issued their report, “World Energy Outlook 2016,” in November 2016. The report addresses the expected transformation of the global energy mix through 2040 as nations attempt to meet national commitments made in the Paris Agreement on climate change, which entered into force on 4 November 2016.

You can download the Executive Summary of WEO-2016 at the following link:

Each year, the EIA issues an Annual Energy Outlook that provides energy industry recent year data and projections for future years. The 2016 AEO includes actual data of 2014 and 2015, and projections to 2040. These data include:

EIA explains that this Summary features two cases: the Reference case and a case excluding implementation of the Clean Power Plan (CPP).

Reference case: A business-as-usual trend estimate, given known technology and technological and demographic trends. The Reference case assumes Clean Power Plan (CPP) compliance through mass-based standards (emissions reduction in metric tones of carbon dioxide) modeled using allowances with cooperation across states at the regional level, with all allowance revenues rebated to ratepayers.

No CPP case: A business-as-usual trend estimate, but assumes that CPP is not implemented.

You can find a good industry assessment of the AEO2016 Summary on the Global Energy World website at the following link:

This report presents the major assumptions of the National Energy Modeling System (NEMS) used to generate the projections in AE02015. A 2016 edition of Assumptions is not yet available. The functional organization of NEMS is shown below.

The predominant renewable sources are solar and wind, both of which are intermittent sources of electric power generation. Except for the following statements, the EIA assumptions are silent on the matter of energy storage systems that will be needed to manage electric power quality and grid stability as the projected use of intermittent renewable generators grows.

All technologies except for storage, intermittents and distributed generation can be used to meet spinning reserves

Pumped storage hydroelectric, considered a nonrenewable storage medium for fossil and nuclear power, is not included in the supply

In my 4 March 2016 post, “Dispatchable Power from Energy Storage Systems Help Maintain Grid Stability,” I addressed the growing importance of such storage systems as intermittent power generators are added to the grid. In the context of the AEO, the EIA fails to address the need for these costly energy storage systems and they fail to allocate the cost of energy storage systems to the intermittent generators that are the source of the growing demand for the energy storage systems. As a result, the projected price of energy from intermittent renewable generators is unrealistically low in the AEO.

Oddly, NEMS does not include a “Nuclear Fuel Module.” Nuclear power is represented in the Electric Market Module, but receives no credit as a non-carbon producing source of electric power. As I reported in my posts on the Clean Power Plan, the CPP gives utilities no incentives to continue operating nuclear power plants or to build new nuclear power plants (see my 27 November 2015 post, “Is EPA Fudging the Numbers for its Carbon Regulation,” and my 2 July 2015 post, “EPA Clean Power Plan Proposed Rule Does Not Adequately Recognize the Role of Nuclear Power in Greenhouse Gas Reduction.”). With the current and expected future low price of natural gas, nuclear power operators are at a financial disadvantage relative to operators of large central station fossil power plants. This is the driving factor in the industry trend of early retirement of existing nuclear power plants.

The following 6 May 2016 announcement by Exelon highlights the current predicament of a high-performing nuclear power operator:

“Exelon deferred decisions on the future of its Clinton and Quad Cities plants last fall to give policymakers more time to consider energy market and legislative reforms. Since then, energy prices have continued to decline. Despite being two of Exelon’s highest-performing plants, Clinton and Quad Cities have been experiencing significant losses. In the past six years, Clinton and Quad Cities have lost more than $800 million, combined.“

“Exelon announced today that it will need to move forward with the early retirements of its Clinton and Quad Cities nuclear facilities if adequate legislation is not passed during the spring Illinois legislative session, scheduled to end on May 31 and if, for Quad Cities, adequate legislation is not passed and the plant does not clear the upcoming PJM capacity auction later this month.”

“Without these results, Exelon would plan to retire Clinton Power Station in Clinton, Ill., on June 1, 2017, and Quad Cities Generating Station in Cordova, Ill., on June 1, 2018.”

Together the Clinton and Quad Cities nuclear power plants have a combined Design Electrical Rating of 2,983 MWe from a non-carbon producing source. For the period 2013 – 2015, the U.S. nuclear power industry as a whole had a net capacity factor of 90.41. That means that the nuclear power industry delivered 90.41% of the DER of the aggregate of all U.S. nuclear power plants. The three Exelon plants being considered for early retirement exceeded this industry average performance with the following net capacity factors: Quad Cities 1 @ 101.27; Quad Cities 2 @ 92.68, and Clinton @ 91.26.

For the same 2013 – 2015 period, EIA reported the following net capacity factors for wind (32.96), solar photovoltaic (27.25), and solar thermal (21.25). Using the EIA capacity factor for wind generators, the largest Siemens D7 wind turbine, which is rated at 7.0 MWe, delivers an average output of about 2.3 MWe. We would need more than 1,200 of these large wind turbines just to make up for the electric power delivered by the Clinton and Quad Cities nuclear power plants. Imagine the stability of that regional grid.

CPP continues subsidies to renewable power generators. In time, the intermittent generators will reduce power quality and destabilize the electric power grid unless industrial-scale energy storage systems are deployed to enable the grid operators to match electricity supply and demand with reliable, dispatchable power.

As a nation, I believe we’re trending toward more costly electricity with lower power quality and reliability.

Venturi Buckeye Bullet-3 (VBB-3) is an all-electric, four wheel drive, land speed record (LSR) car that has been designed to exceed 400 mph (643.7 km/h). The organizations involved in this project are:

Venturi Automobiles:

This Monaco-based company is a leader in the field of high performance electric vehicles. Read more at the Venturi website at the following link:

OSU’s CAR has been engaged in all-electric LSR development and testing since 2000. On 3 October 2004 at the Bonneville Salt Flats in Utah, the original nickel-metal hydride (NiMH) battery-powered Buckeye Bullet reached a top speed of 321.834 mph (517.942 km/h).

In an on-going program known as Mission 01, started in 2009, OSU partnered with Venturi to develop, test, and conduct the land speed record runs of the hydrogen fuel cell-powered VBB-2, the battery-powered VBB-2.5, and the more powerful battery-powered VBB-3. Read more at the OSU / CAR website at following link:

2009: The team’s first world land speed record was achieved on the Bonneville Salt Flats with hydrogen fuel cell-powered VBB-2 at 303 mph (487 km/h).

2010: The team returned to the salt flats with the 700 hp lithium-ion battery powered VBB-2.5 which set another world record at 307 mph (495 km/h); with a top speed at 320 mph (515 km/h).

2013: The 3,000 hp lithium iron phosphate battery-powered VBB-3 was unveiled. Due to the flooding of the Bonneville Salt Flats, the FIA and the organizers of the world speed records program cancelled the 2013 competition.

2014: Poor track conditions at Bonneville persisted after flooding from a summer storm. Abbreviated test runs by VBB-3 yielded a world record in its category (electric vehicle over 3.5 metric tons) with an average speed of 212 mph (341 km/h) and a top speed of 270 mph (435 km/h).

2015: Poor track conditions at Bonneville persisted after flooding from a summer storm. Abbreviated test runs by VBB-3 yielded a world record in its category (electric vehicle over 3.5 metric tons) with an average speed of 212 mph (341 km/h) and a top speed of 270 mph (435 km/h).

You will find a comparison of the VBB-2, VBB-2.5 and VBB-3 vehicles at the following link:

VBB-3 has a 37.2 ft. (11.35 meter) long, slender, space frame chassis that houses eight battery packs with a total of 2,000 cells, two 1,500 hp AC induction motors developed by Venturi for driving the front and rear wheels, a coolant system for the power electronics, disc brakes and a braking parachute, and a small cockpit for the driver. The basic internal arrangement of these components in the VBB-3 chassis is shown in the following diagram.

Source: Venturi

You can see a short video of a test drive of VBB-3 without its external skin at the following link:

VBB-3 currently is being prepared in the OSU / CAR workshop in Columbus, Ohio, for another attempt at the land speed record in summer 2016. A team of about 25 engineers and students are planning to be at the Bonneville Salt Flats in summer 2016 with the goal of surpassing 372 mph (600 km/h).

You can subscribe to Venturi new releases on VBB-3 at the following link:

On 19 September 2016, VBB-3 set an electric vehicle (Category A Group VIII Class 8) land-speed record of 341.4 mph (549 kph), during a two-way run within one hour on the Bonneville salt flats in Utah. You can read the OSU announcement at the following link:

On 3 March 2015, Mitsubishi Electric Corporation announced the delivery of the world’s largest energy storage system, which has a rated output of 50 MW and a storage capacity of 300 MWh. The battery-based system is installed in Japan at Kyushu Electric Power Company’s Buzen Power Plant as part of a pilot project to demonstrate the use of high-capacity energy storage systems to balance supply and demand on a grid that has significant, weather-dependent (intermittent), renewable power sources (i.e., solar and/or wind turbine generators). This system offers energy-storage and dispatch capabilities similar to those of a pumped hydro facility. You can read the Mitsubishi press release at the following link:

The energy storage system and associated electrical substation installation at Buzen Power Plant are shown below. The energy storage system is comprised of 63 4-module units, where each module contains sodium-sulfur (NaS) batteries with a rated output of 200 kW. The modules are double stacked to reduce the facility’s footprint and cost.

Source: Mitsubishi

The following simplified diagram shows how the Mitsubishi grid supervisory control and data acquisition (SCADA) system matches supply with variable demand on a grid with three dispatchable energy sources (thermal, pumped hydro and battery storage) and one non-dispatchable (intermittent) energy source (solar photovoltaic, PV). As demand varies through the day, thermal power plants can maneuver (within limits) to meet increasing load demand, supplemented by pumped hydro and battery storage to meet peak demands and to respond to the short-term variability of power from PV generators. A short-term power excess is used to recharge the batteries. Pumped hydro typically is recharged over night, when the system load demand is lower.

Battery storage is only one of several technologies available for grid-connected energy storage systems. You can read about the many other alternatives in the December 2013 Department of Energy (DOE) report, “Grid Energy Storage”, which you can download at the following link:

This 2013 report includes the following figure, which shows the rated power of U.S. grid storage projects, including announced projects.

Source: DOE

As you can see, battery storage systems, such as the Mitsubishi system at Buzen Power Plant, comprise only a small fraction of grid-connected energy storage systems, which currently are dominated in the U.S. by pumped hydro systems. DOE reported that, as of August 2013, there were 202 energy storage systems deployed in the U.S. with a total installed power rating of 24.6 GW. Energy storage capacity (i.e., GWh) was not stated. In contrast, total U.S. installed generating capacity in 2013 was over 1,000 GW, so fully-charged storage systems can support about 2.4% of the nation’s load demand for a short period of time.

Among DOE’s 2013 strategic goals for grid energy storage systems are the following cost goals:

Near-term energy storage systems:

System capital cost: < $1,750/kW; < $250/kWh

Levelized cost: < 20¢ / kWh / cycle

System efficiency: > 75%

Cycle life: > 4,000 cycles

Long-term energy storage systems:

System capital cost: < $1,250/kW; < $150/kWh

Levelized cost: < 10¢ / kWh / cycle

System efficiency: > 80%

Cycle life: > 5,000 cycles

Using the DOE near-term cost goals, we can estimate the cost of the energy storage system at the Buzen Power Plant to be in the range from $75 – 87.5 million. DOE estimated that the storage devices contributed 30 – 40% of the cost of an energy storage system. That becomes a recurring operating cost when the storage devices reach their cycle life limit and need to be replaced.

The Energy Information Agency (EIA) defines capacity factor as the ratio of a generator’s actual generation over a specified period of time to its maximum possible generation over that same period of time. EIA reported the following installed generating capacities and capacity factors for U.S. wind and solar generators in 2015:

Currently there are 86 GW of intermittent power sources connected to the U.S. grid and that total is growing year-on-year. As shown below, EIA expects 28% growth in solar generation and 16% growth in wind generation in the U.S. in 2016.

Source: EIA

The reason we need dispatchable grid storage systems is because of the proliferation of grid-connected intermittent generators and the need for grid operators to manage grid stability regionally and across the nation.

California’s Renewables Portfolio Standard (RPS) Program has required that utilities procure 33% of their electricity from “eligible renewable energy resources” by 2020. On 7 October 2015, Governor Jerry Brown signed into law a bill (SB 350) that increased this goal to 50% by 2030. There is no concise definition of “eligible renewable energy resources,” but you can get a good understanding of this term in the 2011 California Energy Commission guidebook, “Renewables Portfolio Standard Eligibility – 4th Edition,” which you can download at the following link:

The “eligible renewable energy resources” include solar, wind, and other resources, several of which would not be intermittent generators.

In 2014, the installed capacity of California’s 1,051 in-state power plants (greater than 0.1 megawatts – MW) was 86.9 GW. These plants produced 198,908 GWh of electricity in 2014. An additional 97,735 GWh (about 33%) was imported from out-of-state generators, yielding a 2014 statewide total electricity consumption of almost 300,000 GWh of electricity. By 2030, 50% of total generation is mandated to be from “eligible renewable energy resources,” and a good fraction of those resources will be operating intermittently at average capacity factors in the range from 22 – 33%.

The rates we pay as electric power customers in California already are among the highest in the nation, largely because of the Renewables Portfolio Standard (RPS) Program. With the higher targets for 2030, we soon will be paying even more for the deployment, operation and maintenance of massive new grid-connected storage infrastructure that will be needed to keep the state and regional grids stable.

Here’s a great looking new German all-electric car that was introduced at the March 2014 Geneva Auto Show. It’s a “research” car, not for sale, but an interesting preview of a possible future application of this battery technology in production cars. The flow cell battery capacity in the e-Sportlimousine is reported to be 120 kWh. Compare this to current all-electric cars using lithium-ion battery technology: the Tesla Model S has an 85 kWh battery and a Nissan Leaf has a 24 kWh battery.

Image credit: aetherforce.com

Check out the article on the e-Sportlimousine at the following link, which includes two short videos:

A 2014 press release from NanoFLOWCELL AG describes their battery technology and it’s operational use in the e-Sportlimousine, including a description of the power train and how the car is refueled. See the following link:

Regarding the nano-network technology, Wikipedia reports: “In August 2014, the Quant e-Sportlimousine was approved for testing on public roads using the nanoFLOWCELL® system with a claimed energy or power density of 600 Wh per kilogram (per litre of salt water electrolyte).”

If you are interested in the Tesla lithium-ion battery, check out the Nov 2014, “The Tesla Battery Report”, at the following link: